The present invention relates to subterranean formation stimulation, and, at least in some embodiments, to novel methods for partial monolayer fracturing (“PMF”).
Subterranean wells (such as hydrocarbon producing wells, water producing wells, and injection wells) are often stimulated by traditional hydraulic fracturing treatments. In some traditional hydraulic fracturing treatments, a low viscosity fluid is pumped into a portion of a subterranean formation at sufficiently high rates to fracture the formation. The pressure required to induce fractures in rock at a given depth is known as the “fracture gradient.” In other traditional hydraulic fracturing treatments, a viscous fracturing fluid, which also may function as a carrier fluid, is pumped into a portion of a subterranean formation at a rate and pressure such that the subterranean formation breaks down and one or more fractures are formed. Particulate solids, such as graded sand, may be suspended in a portion of the fracturing or carrier fluid and then deposited in the fractures. These particulate solids, or “proppant particulates,” serve to prevent the fractures from fully closing once the hydraulic pressure is released. By preventing the fracture from fully closing, the proppant particulates aid in forming channels through which fluids may flow.
Commonly used proppant particulates in traditional hydraulic fracturing treatments may comprise substantially spherical particles, such as graded sand, bauxite, ceramics, or even nut hulls. Generally, the proppant particulates are placed in the fracture in a concentration such that they form a tight pack of particulates. Unfortunately, in such traditional operations, when fractures close upon the proppant particulates, the particulates can crush or become compacted, potentially forming non-permeable or low permeability masses within the fracture, rather than desirable high permeability masses; such low permeability masses may choke the flow channels of the fluids within the formation. Furthermore, the proppant particulates may become embedded in particularly soft formations, negatively impacting production.
The success of a fracturing operation depends, at least in part, upon fracture porosity, permeability, and conductivity once the fracturing operation is stopped and production is begun. As used herein, the term “porosity” may indicate the volumetric fraction of a formation, fracture, or proppant pack in which voids exist. Fluids or loose solids may, at times, occupy the voids. As used herein, the term “permeability” may indicate the connective porosity of a formation, and it measures the ability of a formation, fracture, or proppant pack to transmit fluids. As used herein, the term “conductivity” may indicate the permeability of a fracture multiplied by the width of the fracture. Traditional fracturing operations place a large volume of proppant particulates into a fracture, and the permeability of the resultant proppant pack is then related to the interconnected interstitial spaces between the abutting proppant particulates. Thus, the resultant fracture permeability from a traditional fracturing operation is closely related to the strength of the placed proppant particulates (if the placed particulates crush, then the pieces of broken proppant may plug the interstitial spaces) and the size and shape of the placed particulate (larger, more spherical proppant particulates generally yield increased interstitial spaces between the particulates). Such traditional fracturing operations tend to result in packed fractures that have a porosity ranging from about 26% to about 46%.
One way to combat the problem of tight proppant particulate packs of traditional fracturing operations involves placing a much reduced volume of proppant particulates in a fracture to create what has been referred to as a “partial monolayer fracture.” In such operations, the proppant particulates or aggregates within the fracture tend to be no more than a monolayer thick. The proppant particulates may be widely spaced, thus forming a partial monolayer, but they are still sufficient to hold the fracture open and allow for production. Such operations allow for increased fracture permeability due, at least in part, to the fact the produced fluids may flow around widely spaced proppant particulates rather than just through the relatively small interstitial spaces in a tight proppant pack.
While PMF was investigated to some extent in the 1960's, the concept generally has not been successfully applied for a number of reasons. One problem is that successful placement of a partial monolayer of proppant particulates presents unique challenges in the relative densities of the particulates versus the fracturing or carrier fluid: particulates strong enough to hold a fracture open tend to be formed from relatively denser materials, and so may tend to sink to the bottom, which may make transporting those particulates problematic. Alternatively, particulates that can be carried more easily in a fluid may be unable to support the load from the formation once the fracturing pressure is released. PMF techniques have been developed to address this relative density problem. These techniques include methods of increasing the viscosity of the fracturing or carrier fluid and methods of adding weighting agents to the fracturing or carrier fluid.
However, many techniques which address the relative density problem exacerbate another problem commonly found in PMF operations: residue left by fracturing or carrier fluids. Partial monolayer fractures are usually very narrow. The width of such fractures can generally be determined from the dimensions of a single layer of proppant particulates. The permeability of these narrow fractures can be easily compromised by fluids that leave thick, difficult to remove filter cake. FIG. 1 shows a schematic example of a partial monolayer fracture which is compromised by filter cake buildup. A fracture 15 is located in formation 10. Several proppant particulates 20 have been deposited by a fracturing or carrier fluid (not shown) into the fracture 15. The proppant particulates form a single, non-contiguous layer, thus forming a partial monolayer. The fracturing or carrier fluid has left a residue of filter cake 40 coating substantial portions of both the proppant particulates 20 and the exposed surfaces of the formation 10. The open spaces remaining in the fracture 15 form flow channels 30. The permeability of the fracture relates to the fraction of the total cross-sectional area occupied by flow channels 30.
PMF methods that increase the viscosity of the fracturing or carrier fluid or add weighting agents to the fracturing or carrier fluid tend to aggravate the filter cake problem. For example, conventional water based servicing fluids may comprise polysaccharide-based polymers, which may serve as a food source for bacteria. When deposited in the subterranean formation, such polysaccharide-based polymers may produce a bio-mass that may reduce formation permeability. As another example, polymeric gelling agents commonly are added to treatment fluids to provide a desired viscosity. Examples of commonly used polymeric gelling agents include, but are not limited to, biopolymers, polysaccharides such as guar gums and derivatives thereof, cellulose derivatives, synthetic polymers, and the like. When used to make an aqueous-based viscosified treatment fluid, the gelling agent may be combined with an aqueous fluid, and the soluble portions of the gelling agent dissolve in the aqueous fluid. However, the insoluble portions of the gelling agents, such as proteins, cellulose, and fibers, may remain in the aqueous fluid as residue and may enter the pores of both the subterranean formation and the proppant packs. The presence of this residue, among other things, may impair the producing capabilities and/or the permeability of the subterranean formation.